Low Salinity Waterflood in Combination with Surfactant/Polymer; Effects of Kinetics and Brine Composition

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Abstract

Improving the oil recovery beyond what is possible
by conventional methods is a topic of great
interest, and the potential oil recovery for a
field can be improved if unconventional methods
are implemented. Reducing the salinity of
injection water is known to be able to improve the
oil recovery. This has been proven in numerous lab
studies and some field tests, but the underlying
mechanisms are not fully understood. More research
is needed to be able to predict when an
improvement in recovery can be expected, and how
large the improvement would be with low salinity
injection.
This master thesis consists of experimental work
carried out at Uni CIPR, and is a continuation of
earlier research performed at Uni CIPR. The main
goal has been to further study the influence on
oil recovery by low salinity water, in addition to
the effect of combining low salinity injection at
reduced capillarity by injection of surfactants.
Dynamic core displacement experiments have been
performed for six Berea outcrop rocks with
permeability of approximately 400 mD. Four of the
six rocks were saturated with a North Sea crude
oil and aged to shift the wettability to a less
water wet condition. A mixture of crude oil and
octane was used for the displacement experiments.
Brine with different salinities has been injected
into the cores. Injection of 3000 ppm NaCl and
diluted seawater in both secondary and tertiary
mode was performed. Two cores were tested to
investigate if the mechanisms associated with
lowsal could be slower than the timespan of a
typical core flooding experiment. Two other cores
were injected with water with oscillating salinity
to test if a salinity shock could improve the oil
recovery.
The six cores were flooded with a surfactant
solution in tertiary mode, followed by a polymer
injection for mobility control. 3000 ppm NaCl was
injected after the polymer solution.
The results did show some response to lowsal for
the aged cores, around 3-5 % increased production
of original oil in place, but the two cores that
had not been aged did not respond to lowsal. Low
salinity surfactant flooding did improve the
recovery factor from around 60 % to around 75 % of
original oil in place. This was not as much as
previous studies have shown, and the oil
mobilization by surfactant flooding was less than
expected from a capillary desaturation curve.
Injecting a polymer solution after the surfactant
injection, improved the ultimate recovery of oil,
and the efficiency of 600 ppm HPAM seemed to be
better than using 300 ppm.